1. Field of the Invention
The present invention is generally related to hydrocarbon well stimulation, and is more particularly directed to a method for designing matrix treatment, or generally any treatment with a fluid that will react with the reservoir minerals or with chemicals resulting for instance from a previous treatment. The invention is particularly useful for designing acid treatment such as for instance mud acid treatments in sandstone reservoirs.
2. Discussion of the Prior Art
Matrix acidizing is among the oldest well stimulation techniques. It is applied to sandstone formations to remove near-wellbore damage, which may have been caused by drilling, completion, production, or workover operations. Matrix acidizing is accomplished by injecting a mixture of aids (typically hydrofluoric and hydrochloric acids) to dissolve materials that impair well production, as a rule designated as near-wellbore damages.
Matrix treatments ma sandstone reservoirs have evolved considerably since the first mud acid treatment in the 1930s. Treatment fluid recipes have become increasingly complex. Several additives are now routinely used and organic acids are frequently used in high temperature formations to avoid precipitation reactions. Chelating agents are often added to avoid precipitation in formations with high carbonate content.
Substantial production improvements can be achieved by this type of well stimulation technique if treatments are engineered properly. However, matrix treatments are also often a main contributor to reservoir damages. Indeed, the side reactions that occur in almost all mud acid treatments, lead to the formation of precipitates. Precipitates plug pore spaces and reduce permeability and can therefore adversely affect acid treatments if precipitates deposit near the wellbore. Far from the well precipitates are considered to have negligible effect. Moreover, recent studies have made the industry wary of damage due to secondary and tertiary reactions. Accurate prediction of the effectiveness of a matrix treatment involves calculation of the rates of the dissolution and re-precipitation reactions of minerals because the rates dictate where precipitates will be deposited in the reservoir.
Moreover, sandstone mineralogy is quite complex and acid/mineral compatibility as well as acid/crude oil compatibility is often an issue. At present, there is a lack of tools that can predict accurately the reactivity of acids with clays, and consequently, there are treatments currently in practice that use empirical rulesxe2x80x94or at the opposite extreme, rely on extensive costly and time-consuming laboratory testing.
Beyond the treatment fluid selection, the pumping schedule is also a crucial parameter. In The Stimulation Treatment Pressure Record-An Overlooked Formation Evaluation Tool, by H. O. McLeod and A. W. Coulter, JPT, 1969, p. 952-960, a technique is described wherein each injection stage or shut-in during the treatment is considered as a short individual well test. The transient reservoir pressure response to the injection of fluids is analyzed and interpreted to determine the conditions of the wellbore skin and formation transmissibility.
In New Method Proves Value of Stimulation Planning, Oil and Gas Journal, V 77, NO 47, PP 154-160, Nov. 19, 1979, G. Paccaloni proposes a method based on the instantaneous pressure and injection rate values to compute the skin factor at any given time during the treatment. Comparison is made with standard curves calculated for fixed values of skin effect to evaluate skin effect evolution during treatment. Standard curves are generated using Darcy""s equations for steady state, single phase and radial horizontal flow in reservoirs.
A technique presented by Prouvost and Economides enables continuous calculation of the skin effect factor during the course of the treatment and accounts for transient response, see Real-time Evaluation of Matrix Acidizing, Pet. Sci, and Eng., 1987, p.145-154, and Applications of Real-time Matrix Acidizing Evaluation Method, SPE 17156, SPE Production Engineering, 1987, 4, No. 6, 401-407. This technique is based on a continuous comparison of the measured and presumed good reservoir description including the type of model and well and reservoir variables of the subject well.
It is also known from U.S. Pat. No. 5,431,227 to provide a method for matrix stimulation field monitoring, optimization and post-job evaluation of matrix treatments based on calculated and measured bottom hole pressure used in a step rate test to estimate the damage skin.
A number of sandstone acidizing models have been presented in the literature aiming at computing changes in porosity resulting from the dissolution and precipitation of minerals.
In the lumped mineral models, the complex sandstone mineralogy is lumped into characteristic minerals and an average reaction rate for these minerals is determined from core tests. In two mineral models the sandstone minerals are lumped into fast- and slow-reacting groups on the basis of their reactivity with HF. Two mineral models do not account for precipitation reactions. A three mineral lumped model has also been proposed in S. L. Bryant, SPE 22855, An Improved Model of Mud Acid/Sandstone Acidizing, in SPE Annual Technical Conference and Exhibition, 1991, Dallas. The third mineral accounts for the precipitation of amorphous silica. Disadvantages of lumped mineral models are that they do not allow for equilibrium reactions to be modeled and need to be carefully calibrated to the treatment condition and formation of interest. Therefore, these models are not applicable to fluids systems containing weak acids (e.g. most organic acids) and chelating agents and are not reliable outside the calibrated region.
The equilibrium approximation is another approximation that is frequently used for the design of matrix treatments. This model has been presented in Walsh, M. P., L. W. Lake, and R. S. Schechter, SPE 10625, A Description of Chemical Precipitation Mechanisms and Their Role in Formation Damage During Stimulation by Hydrofluoric Acid, in SPE International Symposium on Oilfield and Geothermal Chemistry, 1982, Dallas. In the equilibrium approximation it is assumed that the reactions are much faster than the contact time of the minerals with the acids. The equilibrium constants for the reactions are usually better known than the rate constants, so large reaction sets can be included and complex sandstone mineralogy can be accounted for without speculating on the reactions and rate laws as is necessary in the lumped mineral approach. Unfortunately, the assumption that the reactions are much faster than the contact time is not valid for the injection rates used in most acid treatments and thus the equilibrium approach is useful only as an indicator for precipitation. The question that must be answered for a successful design is not if but where precipitation will occur. An equilibrium model alone with no time dependence cannot answer this question.
To address this discrepancy in the equilibrium models, partial local equilibrium models have been proposed and first described in Sevougian, S. D., L. W. Lake, and R. S. Schechter, KGEOFLOW: A New Reactive Transport Simulator for Sandstone Matrix Acidizing, SPE Production and Facilities, 1995: p. 13-19 and in Li, Y., J. D. Fambrough, and C. T. Montgomery, SPE 39420, Mathematical Modeling of Secondary Precipitation from Sandstone Acidizing, SPE International Symposium on Formation Damage Control, 1998, Lafayette. The partial equilibrium approach combines the kinetic and equilibrium approaches. Slow reactions are modeled with a kinetic model, and an equilibrium model is used for fast reactions. This computation scheme enables comprehensive and flexible modeling of sandstone acidizing, but traditionally suffered from several disadvantages. First, accurate computation of the activity coefficients for high acidic and high ionic strength solutions is difficult. Second, due to inefficient numerical algorithms numerical convergence was a frequent problem. Therefore, only 1-2 precipitated mineral species could be practically simulated. Third, only a limited thermodynamic data was available. Hence, simulations for hot reservoirs and with nontraditional fluid systems were not possible.
The previous models are applicable to a limited range of temperatures, injection rates and mineral composition. So yet, despite the important risk of damaging a reservoir, no satisfactory method for modeling matrix treatments over a much broader range of these variables, to make the model more reliable for extrapolating laboratory data to field conditions.
This failure of the existing models is all the more critical that treatment fluid recipes have become increasingly complex. Several additives are now routinely added, organic acids are frequently used in high temperature formations to avoid precipitation reactions and chelating agents are often added to avoid precipitation in formations with high carbonate content.
The subject invention is directed to a method for designing matrix treatments, and more particularly, for stimulation with reactive fluid in sandstone formations, even though the invention extends to other areas such as carbonate acidizing, scale inhibition and related fields. In particular, according to a first embodiment, the invention relates to a method for selecting the optimal treatment wherein reservoir characteristics including reservoir minerals are obtained and a treatment fluid comprising a mixture of chemical species is designed to further select a subset of chemical reactions that can occur between the reservoir minerals and the treatment fluid the reaction kinetic and equilibrium data on the minerals and chemical species of interests, and depending on the predicted damages consecutive to those reactions, the stimulation treatment is adjusted to optimize the results. In other words, the invention proposes a virtual chemical laboratory that makes it possible to simulate a large number of laboratory tests.
In a second embodiment of the invention, the method further includes modeling a reservoir core having a length, a diameter and a permeability so that the invention makes it possible to simulate core tests. The invention also provides a way to simulate sequential treatments where successions of treatment fluids are injected at specific rates.
In a third embodiment of the invention, the method further includes scaling up the treatment to a reservoir using a mathematical model to predict damages resulting from the treatment. In a most preferred embodiment, the invention includes selecting a treatment, carrying out the treatment on a well while real time damage are computed based on bottomhole pressure and injection rate and simultaneously, performing a simulation scaled up to the reservoir to compare the predicted damages and the computed damages and adjusting the treatment if required.
In the preferred embodiments of the invention, the three flow geometries have been implemented: (1) batch, (2) core and (3) reservoir geometries. The batch flow geometry approximates the reactions occurring in a flask or a beaker, the core flow geometry approximates linear flow in cores such as that in laboratory core flooding experiments, and the reservoir flow geometry approximates flow in a single layer, radially symmetric reservoir. The batch and core flow geometries provide a means for validating the mathematical model, so that the predictions for the reservoir can be made with more confidence.
The model generated by the method of the subject invention can facilitate optimization of matrix treatments by providing a rapid quantitative evaluation of various treatment strategies for a formation. Stimulation with non-traditional fluid recipes containing mixtures of inorganic and organic acids, and chelating agents can be readily computed. The computed values can then be used in an economic model to justify the additional costs associated with the use of the non-traditional fluids. Apart from optimizing matrix treatments, the method of the subject invention can also be used as a development tool for new fluid systems, as a tool for prediction and removal of inorganic scale and for fluid compatibility testing such as that required in waterflooding projects.
The method of the subject invention combines a geochemical simulator to an extensive database of thermodynamic properties of aqueous chemical species and minerals. The subject invention overcomes many limitations of previous simulators. Chemical equilibrium calculations can be performed between any number of minerals and aqueous solutions, whereas previous simulators were limited to only one or two precipitated minerals. Additionally, any number of kinetically controlled reactions can be simulated with user-defined kinetics.
The modeling method of the subject invention is a finite-difference geochemical simulator capable of modeling kinetic and/or equilibrium controlled reactions in various flow geometries. The mathematical formulation provides the capability to model an arbitrary combination of equilibrium and kinetic reactions involving an arbitrary combination of equilibrium and kinetic reactions involving an arbitrary number of chemical species. This flexibility allows the simulation model to act as a pure kinetic model if no equilibrium are specified or as a pure equilibrium model if both kinetic and equilibrium reactions are specified. A semi-implicit numerical scheme is used for integration in time for kinetic reactions. This scheme provides greater numerical stability compared to explicit schemes, especially at high temperature. A Gibbs free energy minimization algorithm with optimized stoichiometry is used in computing chemical equilibrium between aqueous species and minerals. Base specie switching is implemented to improve convergence. The resulting algorithm for chemical equilibrium calculation is of greater numerical stability and is more efficient than prior art algorithms based on a non-stoichiometric approach.
The treatment design preferably includes variables such as fluid type, composition, volume, pumping sequence and injection rates. A database is used to get the reaction kinetics data. If insufficient data is available, laboratory experiments may be conducted, preferably using multiple linear core flow tests for a range of injection rates.
The reservoir characteristics typically include mineralogy data, permeability and preferably, an estimate of the quantity and depth of damage such as scales, fines migration or drilling-related damages including the initial damage skin. This estimate can be made for instance based on nodal analysis or available mud and resistivity logs. The reservoir characteristics may be stored in a database and if not already available, are obtained by geochemical logging or from core analysis and further stored in the database for further use.
The model is preferably calibrated with data including effluent analysis and permeability evolution (including predicted damages). Sensitivity analysis may be also performed to optimize the design variables and select improved treatment design.
Once an optimized design has been selected, the execution of the treatment can begin and damage skin can be computed on a real time basis. This allows a comparison with the predicted damages and, if appropriate, adjustment of the treatment.
Specifically, the invention comprises data collection, design optimization, execution and evaluation. In the execution phase, the damage is computed in real time from either calculated or measured values of bottomhole pressure and injection rate. It can then be compared to the computed damage skin with that predicted by the mathematical model. The model can thereafter be refined by better estimates for type, quantity and depth of damage to match the measured values and, if needed, appropriate changes to the treatment design are performed.
Post treatment data, such as flowback analysis, production data and production logs, are used to further refine the mathematical model and the estimates of damage depth and quantity. The treatment data can finally be uploaded into the database so it can be used in improving future treatment designs.
The method of the subject invention facilitates treatment design with the methodology described above. This can be implemented with a mathematical model and databases. The mathematical model may comprise the following components:
1. Algorithm for automatic selection of the various applicable chemical reactions for the defined system of fluids and minerals
2. Modeling of organic acids and chelating agent chemistry for sandstone acidizing
3. Algorithm for scale up from core to reservoir
4. Modeling of multiple precipitates
The mathematical model can be extended later to other processes such as carbonate acidizing, scale inhibition, or other mechanisms that involve fluid/reservoir interaction.
According to a preferred embodiment, the method of the subject invention incorporates extensive databases of minerals, chemical reactions, fluids and reservoirs in order to feed the mathematical model with accurate geological, physical and reactivity data, thereby ensuring the success of the process. Users preferably have the ability to create new components (fluids, minerals, reactions) and add them to the database for future use. This allows continued expansion of the methodology of the subject invention to new systems and new processes. In accordance with the teachings of the subject invention, chemical equilibrium calculations can be performed between any number of minerals and aqueous solutions.
In the preferred embodiment of the invention, the essential steps are stored on a CD-ROM device. In another preferred embodiment, the method/process is downloadable from a network server, or an internet web page. Moreover, the present invention can be subsumed using a software developed to assist acid treatments.